Morgan Stanley MLP & Natural Gas Corporate Access Day

Transcription

1 Morgan Stanley MLP & Natural Gas Corporate Access Day Kim Dang Chief Financial Officer March 16, 010

2 Forward Looking Statements This presentation contains forward looking statements. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. In particular, statements, express or implied, concerning future actions, conditions or events, future operating results or the ability to generate revenues, income or cash flow or to make distributions are forward-looking statements. Forward looking statements are not guarantees of performance. They involve risks, uncertainties and assumptions. Future actions, conditions or events and future results of operations of Kinder Morgan Energy Partners, L.P. and Kinder Morgan Management, LLC may differ materially from those expressed in these forwardlooking statements. Many of the factors that will determine these results are beyond Kinder Morgan's ability to control or predict. These statements are necessarily based upon various assumptions involving judgments with respect to the future, including, among others, the ability to achieve synergies and revenue growth; national, international, regional and local economic, competitive and regulatory conditions and developments; technological developments; capital and credit markets conditions; inflation rates; interest rates; the political and economic stability of oil producing nations; energy markets; weather conditions; environmental conditions; business and regulatory or legal decisions; the pace of deregulation of retail natural gas and electricity and certain agricultural products; the timing and success of business development efforts; terrorism; and other uncertainties. There is no assurance that any of the actions, events or results of the forward-looking statements will occur, or if any of them do, what impact they will have on our results of operations or financial condition. Because of these uncertainties, you are cautioned not to put undue reliance on any forward-looking statement.

3 Use Of Non-GAAP Financial Measures The non-generally accepted accounting principles ("non-gaap") financial measures of distributable cash flow before certain items (both in the aggregate and per unit), segment earnings before depreciation, depletion, amortization and amortization of excess cost of equity investments ("DD&A") and certain items, segment distributable cash flow before certain items, and earnings before interest, taxes and DD&A ("EBITDA") before certain items are included in this presentation. Our non-gaap financial measures should not be considered as alternatives to GAAP measures such as net income or any other GAAP measure of liquidity or financial performance. Distributable cash flow before certain items and EBITDA before certain items are significant metrics used by us and by external users of our financial statements, such as investors, research analysts, commercial banks and others, to compare basic cash flows generated by us to the cash distributions we expect to pay our unitholders on an ongoing basis. Management uses these metrics to evaluate our overall performance. Distributable cash flow before certain items also allows management to simply calculate the coverage ratio of estimated ongoing cash flows to expected cash distributions. Distributable cash flow before certain items and EBITDA before certain items are also important non-gaap financial measures for our unitholders because they serve as indicators of our success in providing a cash return on investment. These financial measures indicate to investors whether or not we typically are generating cash flow at a level that can sustain or support an increase in the quarterly distributions we are paying pursuant to our partnership agreement. Our partnership agreement requires us to distribute all available cash. Distributable cash flow before certain items, EBITDA before certain items and similar measures used by other publicly traded partnerships are also quantitative measures used in the investment community because the value of a unit of such an entity is generally determined by the unit's yield (which in turn is based on the amount of cash distributions the entity pays to a unitholder). The economic substance behind our use of distributable cash flow before certain items and EBITDA before certain items is to measure and estimate the ability of our assets to generate cash flows sufficient to make distributions to our investors. We define distributable cash flow before certain items to be limited partners' pretax income before certain items and DD&A, less cash taxes paid and sustaining capital expenditures for KMP, plus DD&A less sustaining capital expenditures for Rockies Express and Midcontinent Express, our equity method investees, less equity earnings plus cash distributions received for Express and Endeavor, two additional equity investees. Distributable cash flow before certain items per unit is distributable cash flow before certain items divided by average outstanding units. Segment distributable cash flow before certain items is segment earnings before certain items and DD&A less sustaining capital expenditures. In certain instances to calculate segment distributable cash flow, we also add DD&A less sustaining capital expenditures for Rockies Express and Midcontinent Express, our equity method investees. We define EBITDA before certain items as pretax income before certain items, plus interest expense and DD&A, including the DD&A of REX and MEP, our equity method investees. "Certain items" are items that are required by GAAP to be reflected in net income, but typically either (1) do not have a cash impact, for example, goodwill impairments, allocated compensation for which we will never be responsible, and results from assets prior to our ownership that are required to be reflected in our results due to accounting rules regarding entities under common control, or () by their nature are separately identifiable from our normal business operations and in our view are likely to occur only sporadically, for example legal settlements, hurricane impacts and casualty losses. Management uses this measure and believes it is important to users of our financial statements because it believes the measure more effectively reflects our business' ongoing cash generation capacity than a similar measure with the certain items included. For similar reasons, management uses segment earnings before DD&A and certain items and segment distributable cash flow before certain items in its analysis of segment performance and managing our business. We believe segment earnings before DD&A and certain items and segment distributable cash flow before certain items are significant performance metrics because they enable us and external users of our financial statements to better understand the ability of our segments to generate cash on an ongoing basis. We believe they are useful metrics to investors because they are measures that management believes are important and that our chief operating decision makers use for purposes of making decisions about allocating resources to our segments and assessing the segments' respective performance. We believe the GAAP measure most directly comparable to distributable cash flow before certain items and to EBITDA before certain items is net income. Segment earnings before DD&A is the GAAP measure most directly comparable to segment earnings before DD&A and certain items and segment distributable cash flow before certain items. Our non-gaap measures described above should not be considered as an alternative to GAAP net income, segment earnings before DD&A or any other GAAP measure. Distributable cash flow before certain items, segment earnings before DD&A and certain items, segment distributable cash flow before certain items and EBITDA before certain items are not financial measures in accordance with GAAP and have important limitations as analytical tools. You should not consider any of these non-gaap measures in isolation or as a substitute for an analysis of our results as reported under GAAP. Because distributable cash flow before certain items and EBITDA before certain items exclude some but not all items that affect net income and because these measures are defined differently by different companies in our industry, our distributable cash flow before certain items and EBITDA before certain items may not be comparable to similarly titled measures of other companies. Segment earnings before DD&A and certain items and segment distributable cash flow have similar limitations. Management compensates for the limitations of these non-gaap measures by reviewing our comparable GAAP measures, understanding the differences between the measures and taking this information into account in its analysis and its decision making processes. A reconciliation of these measures to the most comparable GAAP measures is provided on our website at: 3

4 Current Capital Structure Kinder Morgan Energy Partners, L.P. Market Equity $19.0B Debt 10.4B Enterprise Value $9.4B 010E EBITDA (c) 010E DCF (d) Additional Shares KMR (NYSE) KMR (LLC) 87 million i-units i (a) KMP $3.B $.4B Cash Distribution KMP (NYSE) (Partnership) 13 million units (a) Incentive Distribution 75MM 191MM MM 1MM Public Float General Partner (a) KMP market equity based on 13 million common units (includes 5.3 million Class B units owned by Kinder Morgan, Inc.; Class B units are unlisted KMP common units) at a price of $65.1 and 87 million KMR shares at a price of $58.7, as of 1-Mar-010 (b) Debt balance as of 31-Dec-009, excludes the fair value of interest rate swaps, net of cash (c) A definition of this measure is outlined on the Non-GAAP Financial Measures slide (d) KMP Distributable Cash Flow; a definition of this measure is outlined on the Non-GAAP Financial Measures slide 4

5 The Kinder Morgan Strategy Focus on stable, fee-based assets which are core to the energy infrastructure of growing markets Increase utilization of assets while controlling costs Classic fixed cost businesses with little variable costs Improve productivity to drop all top-line growth to bottom line Leverage economies of scale from incremental acquisitions and expansions Reduce needless overhead Apply best practices to core operations Maximize benefit of a unique financial structure which fits with strategy Same Strategy Since Inception MLP avoids double taxation, increasing distributions from high cash c flow businesses Strong balance sheet allows flexibility when raising capital for acquisitions / expansions 5

6 Unmatched Footprint Jet Trans Fuel Mountain Pipeline Cochin ENERGY PARTNERS, L.P. Largest independent transporter of petroleum products in the U.S. Transport ~1.9 million barrels per day (Bbl/d) nd largest transporter of natural gas in U.S. (a) Own an interest in or operate over 4,000 miles of interstate / intrastate pipeline Largest provider of contracted natural gas treating services in U.S. Largest transporter of CO in U.S. Transport ~1.3 Bcf/d of CO nd largest oil producer in Texas Produce ~56 MBbl/d of crude Largest independent terminal operator in U.S. Own an interest in or operate ~180 liquids / dry bulk terminals (b) ~107 million barrels of domestic liquids capacity (c) Handled ~78 million tons of dry bulk products in 009 Largest handler of petcoke in U.S. Only Oilsands pipeline serving Vancouver B.C. / Washington state TMPL transports ~300 MBbl/d to Vancouver / Washington state (a) Includes NGPL (b) Excludes 34 transload facilities (c) Includes leased capacity Pacific Northern TransColorado CALNEV Pacific PRODUCTS PIPELINES PRODUCTS PIPELINES TERMINALS TRANSMIX FACILITIES NATURAL GAS PIPELINES REX KMCO Express Wink Yates KMIGT SACROC FAYETTEVILLE EXPRESS PIPELINE NATURAL GAS STORAGE NATURAL GAS PROCESSING GAS TREATERS Trailblazer Platte MEP FEP 3 Claytonville KMTejas Cypress 4 KMTP 9 5 KMLP CO PIPELINES CO OILFIELDS 4 REX CRUDE OIL PIPELINES (,3,8) TERMINALS 3 3 Plantation Central Florida 6 4 PETROLEUM PIPELINES PETROLEUM PIPELINES TERMINALS INDICATES NUMBER OF FACILITIES IN AREA KM HEADQUARTERS

7 Well-diversified Cash Flow 58% Liquids 4% Bulk CO 8% CO transport and sales 7% oil production related Production hedged (a) : 010=73% ($57/Bbl) 011=60% ($63) 01=3% ($8) 013=14% ($89) 014=5% ($85) Terminals Geographic and product diversity KMP 010E Segment DCF Profile (b) 30% 17% 5% 8% 0% Kinder Morgan Canada Natural Gas Pipelines 59% Interstate (c) 41% Texas Intrastate Products Pipelines 59% Pipelines 36% Associated Terminals (d) 5% Transmix (a) 010 budget; based on Netherland, Sewell reserve report; includes heavier NGL components (C4+); where collars are used, pricing incorporated into average hedge price is the collar floor; incorporates swaps and puts at strike price net of premium (b) Budgeted 010 segment distributable cash flow, as defined on the Non-GAAP Financial Measures slide (c) Includes upstream segment; ~4% of total natural gas pipeline segment (d) Terminals are not FERC regulated except portion of CALNEV 7

8 Delivering 13 Years Of Consistent Growth Total Distributions (GP + LP) ($MM) (a) Annual LP Distribution Per Unit (a,c a,c) $,500 $,000 $1,500 $1,000 $500 $0 $17 $30 GP (b) LP $1,469 $1,16 $1,65 $978 $87 $701 $548 $333 $153 $ CAGR = 43% $1,854 $,13 $, E $4.50 $4.00 $3.50 $3.00 $.50 $.00 $1.50 $1.00 $0.50 $0.00 $1.71 $1.4 $1.43 $0.94 $ CAGR = 15% $.44 $.63$.87 $.15 $3.13 $3.6$3.48 $4.40 $4.0 $ E 4.5x 4.0x 3.5x 3.0x.5x.0x 1.5x 1.0x 0.5x 0.0x 3.5x 3.x 3.9x 3.9x (a) Approximately $3 million of budgeted distribution coverage in 010 (b) Includes % GP interest (c) Annual LP distribution, rounded to decimals where applicable (d) Debt is net of cash and excludes fair value of interest rate swaps Net Debt to EBITDA (d) 3.5x 3.7x 3.8x 3.5x 3.x 3.3x 3.4x 3.4x 3.8x 3.6x E 8

9 Significant Historical Returns (a) KMP: 7% CAGR Since 96 (b) KMR: 14% CAGR Since 01 (c) $,500 $,50 $,000 $1,750 $1,500 $1,50 $1,000 $750 $500 Dollars KMP = $,307 AMZ (d) = $705 $50 $35 $100 $0 S&P 500 = $195 $0 S&P 500 = $ May-001 Dec-96 Dec-98 Dec-00 Dec-0 Dec-04 Dec-06 Dec-08 Dec-00 Dec-01 Dec-0 Dec-03 Dec-04 Dec-05 Dec-06 Dec-07 Dec-08 Dec-09 $350 $315 $80 $45 $10 $175 $140 $105 $100 $70 Source: Bloomberg (a) All returns calculated on daily basis through 1-Mar-010 except the 009 return, which is through 31-Dec-009; assume dividends/distributions reinvested in index/stock/unit (b) Start date 31-Dec-1996 (c) Start date 14-May-001; KMR Initial public offering; KMP CAGR over same period is 15% (d) Alerian MLP index (e) Start dates for -year, 3-year and 5-year return calculations are 31-Dec-007, 9-Dec-006 and 31-Dec-004, respectively 9 Dollars Total Return 009 -year (e) 3-year (e) KMP 45% 43% 71% KMR 50% 33% 65% AMZ (d) 76% 1% 37% S&P 500 6% -17% -13% 5-year (e) 11% 113% 83% 6% AMZ (d) = $36 KMR = $313

10 KMR 101 (a) KMR is KMP KMR shares are pari passu with KMP units 10% KMR Discount to KMP KMR dividend equal to KMP cash distribution, but paid in additional ~7% avg discount 5% shares; effectively a dividend reinvestment program since 001 IPO Share dividend reduces KMP s s external capital funding needs 0% Cash flow is generated to pay cash dividend but paid in additional shares, reinvesting cash into growth projects -5% Like KMP units, KMR shares are tax efficient but with simplified -10% tax reporting -15% ~1% avg discount Capital gains treatment since Nov 08-0% No K-1 K 1 (1099 if you sell shares, otherwise no tax documents) 14-May-001 Dec- Dec- Dec- Dec- Dec- Dec- Dec- Dec- Dec- IRA-friendly - no UBTI or state tax filings Offshore investors can more easily own KMR market cap = $5.1 billion, ~1/4 of total KMP capitalization KMR has generated strong returns for investors and trades at a significant s Management Purchases of KMR & KMP (e) discount to KMP (millions) 50% total return in 009 $ % compound annual total return since 01 IPO vs. 14.7% for KMP, $8 14.3% for the Alerian MLP index and 1.0% for the S&P 500 $6 Historical ~7% discount since IPO $4 $9.4 Current ~10% discount $ $4.5 Insiders prefer KMR $0 Management has purchased KMR at a rate of :1 vs KMP KMR KMP (a) All figures through / as of 1-Mar-010, except 009 total return which is through 31-Dec-009; see footnotes on slide 10 for explanation of total return calculations (b) Calculation of share dividend: KMP quarterly cash distribution per unit KMR 10-day avg price prior to x-date = fractional share paid for every KMR share owned, e.g. $1.05 $56.97 = ; example reflects actual KMR share dividend calculated for 4Q 009, paid on 1-Feb-010; refer to K for more information (c) Can be held directly; in-kind dividends not subject to ECI rules and branch profits withholdings, no FIRPTA issues (d) KMR market equity based on 87 million KMR shares outstanding and share price of $58.7 as of 1-Mar-010 (e) Purchase of KMR shares and KMP units by directors and officers of KMR/KMP since the KMR IPO in 001, as reported in SEC Form 4 filings 10 Dec- 09

11 Promises Made, Promises Kept Promises Made Budgeted Distribution per unit: 000: $ : $ : $ : $ : $ : $ : $ : $ : $ : $ E: $4.40 Promises Kept Actual Distribution per unit: 000: $ : $.15 00: $ : $ : $ : $ : $ : $ : $ : $4.0 Missed LP distribution target 1 time in past 10 years 11

12 Stable Asset Base Volume Security Remaining Contract Life (b) Pricing Security Regulatory Security Commodity Price Exposure Natural Gas Pipelines Interstate: virtually all take or pay Intrastate: ~78% take or pay (a) Transportation: 8.9 yrs (c) Storage:.7 yrs Interstate: fixed based on contract Intrastate: primarily fixed margin Interstate: regulatory return mitigates downside; higher recourse rates for increased costs Intrastate: essentially market-based Interstate: no direct Intrastate: limited Products Pipelines volume based Barriers to Entry High High High High High (a) Transportation for intrastate pipelines includes term purchase and sale portfolio (b) Volume-weighted, except Terminals which is weighted based on 010 budgeted revenues (c) Includes newbuild pipelines (REX, MEP and KMLP); newbuild pipeline capacity generally subscribed for a 10-year initial term (d) Doesn t reflect SACROC contract renewal (e) Based on revenue assuming an oil price of ~$84/Bbl; includes sales we make to our O&G business; eliminating sales to O&G = 8% fixed / 18% tied to oil price (f) % of 010 expected production, includes heavier NGL components (C4+) CO S&T: minimum volume guarantee Terminals Liquids: take or pay Bulk: minimum volume guarantee, requirements Kinder Morgan Canada No volume risk not applicable S&T: 3.1 yrs (d) ~3 yrs.1 yrs PPI + 1.3% regulatory return mitigates downside no direct S&T: 68% fixed (e) O&G: volumes 73% hedged (f) based on contract; typically fixed or tied to PPI fixed based on toll settlement primarily unregulated not price regulated regulatory return mitigates downside S&T: 3% tied to oil price (e) O&G: volumes 7% no direct no direct unhedged (f) 1

13 Asset Footprint And Management Expertise Have Led To Growth Opportunities ENERGY PARTNERS, L.P. Products Pipelines Natural Gas Pipelines Industry Rank (a) Launch Pad CFPL, CALNEV, Charter Triad, Cochin 1 st SFPP multiple terminal acquisitions from majors Rockies and Texas intrastate nd dropdowns, Tejas, TransColorado KN Energy dropdown, Dayton storage, Crosstex treating, GMX CO 1 st SACROC, Yates, Claytonville & Shell CO Katz fields, Wink pipeline GATX, TGS, Vancouver Wharves, US Development, Slay Terminals 1 st Hall Buck on average, acquired ~$15MM per year over last 5 years Kinder Morgan Canada Terasen Led to: Acquisitions (b) Led to: Internal Growth (b) Carson terminal, East Line & Northline expansions Ethanol buildout in Southeast/Westcoast REX, MEP, KMLA & FEP greenfield projects Texas Intrastate storage expansions Trailblazer & TransColorado expansions SACROC & Yates development Southwest Colorado expansion Katz EOR greenfield project Pasadena, Galena Park, Perth Amboy, Carteret, Pier IX & Geismer expansions Edmonton North 40 greenfield project TMPL dropdown 75MBbl/d expansion of TMPL (a) See slide 7 for explanation of basis for industry rankings (b) Not an exhaustive list of acquisitions or internal growth projects (c) Since the beginning of 1997 On average, KMP has invested ~$1.5 billion in growth capital per year in its business segments (c) 13

14 Sources of Future Growth Natural Gas Pipelines Products Pipelines / Terminals Segments CO Growth Drivers Cheap, abundant, domestic energy source Shifting supply from multiple basins U.S. demand for natural gas expected to increase by ~17 Bcf/d (a) Over $100 billion of new pipeline infrastructure estimated between 010 and 030 (b) Natural gas is the logical fuel of choice for economical clean burning electricity Diversity of product specs RFS requires a nearly two-fold increase in use of renewable fuels through 0 (c) Customers desire for optionality at terminal locations (export and import capabilities and multiple modes of inbound and outbound transportation, e.g. water, rail, truck access) Billions of barrels of domestic oil still in place Continuing technology improvements Development of new basins Fragmented ownership of oilfields Continued need to move Canadian crude and Kinder Morgan Canada refined products to Westcoast (a) Source: Wood Mackenzie long-term outlook, Dec-009 (b) Source: INGAA natural gas infrastructure study, Oct-009 (c) RFS (U.S. Renewable Fuels Standard) requires increase from 13 Bgal/yr in 010 to 36 Bgal/yr in 0) KM Opportunity Leverage Footprint Full-year impact of REX, MEP, KMLA Completion of construction of FEP in 010 Leverage KM s pipeline connectivity and expertise into pipeline/storage expansions and acquisitions in current and new basins Expand services to customers (i.e. Treating, G&P, etc) Committed ~$500MM to handle renewable fuels to date and continue to expand across our asset base Location of facilities and ability to provide flexibility to customers keeps customers at terminals and provides for expansions Consolidate mom and pop bulk terminals Look for acquisitions from the majors Continue buildout of SACROC and Yates Katz expansion project Utilize CO expertise to evaluate oilfield acquisitions and new pipeline projects Flexibility for staged expansions or one large expansion to Westcoast 14

15 ~$0 Billion in Capital Invested (a,b) (billions) Total Invested by Type (a,b) $3.5 $3.0 Total Invested by Year (a) JV Contributions Expansion Acquisition $.9 $.7 $3.3 $1 $9 $6 $3 $.4 $8.7 $8.8 $.5 $.0 $1.5 $1.0 $0.5 $0.0 $1.6 $1.1 $0.8 $1.9 $1.3 $1.3 $1. $0.9 $0.9 (a) For joint-ventures, reflects our equity contributions (b) , does not include 010 budget $ E $0 $8 $6 $4 $ $0 Total Invested by Segment (a,b) $.4 $5.0 $4.3 Natural Gas Pipelines Expansions Products Pipelines $3.5 $3.4 Acquisitions $1.3 CO Terminals Kinder Morgan Canada 15

16 $1.5 Billion in Growth Expenditures Planned for 010 (millions) 010 Budgeted Growth Expenditures CO 8% % Natural Gas Pipelines (a) Terminals 13% 19% 7% 0.% 11% Products Pipelines KM Canada Identified Acquisitions Announced Acquisitions (b) (a) Includes equity contributions to joint ventures (b) $195 million ethanol terminal acquisition from U.S. Development Group and $95 million Slay bulk terminal acquisition 16

17 Returns on Capital Segment ROI (a) : Products Pipelines 11.9% 11.8% 1.8% 1.9% 1.4% 11.6% 11.8% 13.% 1.5% 13.4% Natural Gas Pipelines CO Terminals Kinder Morgan Canada KMP ROI 1.3% 1.7% 1.6% 13.1% 13.6% 14.3% 14.4% 14.1% 14.9% 13.9% KMP Return on Equity 17.% 19.4% 0.9% 1.7% 3.4% 3.9%.6%.9% 5.% 5.% Note: A definition of this measure may be found in the appendix to the Analyst Conference presentation dated 8-Jan-010, which is available on our website at (a) G&A is deducted to calculate the KMP ROI, but is not allocated to the segments and therefore not deducted to calculate the individual Segment ROI 17

18 Balance Sheet Remains Solid (a) (millions) Credit Summary Credit Metrics Debt / EBITDA (b,c b,c) EBITDA / Interest (c) L-T T Debt Rating FY x 6.4x (d) Baa/BBB/BBB Budgeted Yr-end x 6.1x Revolver Liquidity (e) Total Bank Credit Less: Borrowings Letters of Credit Liquidity $1,787 (300) (83) $1,04 Long-term Debt Maturities (f) Nov $6 $707 $957 $507 $501 (g) (a) Figures as of 31-Dec-009, except where noted (b) Debt balance excludes fair value of interest rate swaps and is net of cash (c) EBITDA and interest are trailing 1 months, includes our proportionate share of REX/MEP DD&A (d) Rated by Moody s, S&P and Fitch, respectively (e) Existing KMP revolver matures Aug-010 (f) Maturities of long-term debt; excludes borrowings under its revolving credit facility (g) Excludes 10-yr bond with optional 3-yr put (stated maturity 019) 18

19 Risks Regulatory Pacific Products Pipeline FERC/CPUC case Periodic rate reviews Unexpected policy changes Crude Oil Production Volumes Crude Oil Prices Budget assumes $84/Bbl realized price on unhedged barrels 010 Sensitivity is ~$6 million DCF per $1/Bbl change in crude oil o prices Economically Sensitive Businesses (e.g., steel terminals) Environmental Terrorism Interest Rates ~50% floating rate debt The full-year impact of a 100-bp increase in rates equates to an approximate $55 million increase in interest expense 19

20 Attractive Value Proposition Unparalleled asset footprint Established track record Industry leader in all business segments Experienced management team Supportive general partner Transparency to investors Attractive returns driven by combination of yield plus growth 0

21